Method for determining  a steam dryness factor

ABSTRACT

The present invention provides an easy, field applicable, and extra-equipment method for determining steam dryness directly under thermal high-viscosity oil stimulation. The technical effect is achieved by adding the gas non-condensed in a well under flooding to the saturated steam pumpdown. The non-condensed gas occurrence of the mixture will vary partial steam pressure. In doing so, the steam condensation temperature will vary too. The borehole temperature or pressure measurements can be used to evaluate the steam dryness.

The present invention relates to methods for determining steam drynessunder thermal high-viscosity oil reservoir stimulation.

Well bottom zone steam treatment finds a wide application in thepetroleum industry for stimulating heavy viscous oil production. Theroutine method of steam stimulation applied is to inject the designedcoolant into injection holes. More often than not for a coolant, the0.7-0.8-dry saturated steam is used. The steam dryness is one of thecritical features of the steam injection-base thermal methods of theheavy oil development. While delivered from the surface to theperforation depth, a portion of the steam should condense to water dueto surrounding rock heat exchange. In case of deep reservoir beds, lackof thermal well insulation, low-speed flooding and so on, the steam cancompletely be condensed to hot water. This will breach the concepts ofthermal development methods (steam drive, steam well treatment) andreduce efficiency thereof due to rapid internal energy loss when steamcondensed.

The known in the art methods for determining steam dryness in thedownhole environment are based on well steam sampling, the use ofcomplicated measurement devices or rather expensive chemical agents astracers.

So, for example, U.S. Pat. No. 5,470,749, 1995, describes a method forcontrolling steam dryness wherein the well steam is sampled and mixedwith low amount of the surface active agent; RF Patent #1046665, 1983,describes a method for determining steam dryness that involves measuringstatic pressure and two reference parameters functionally related tosteam dryness.

The closest analog to the invention claimed is a method for determiningwell steam dryness that includes the steam flooding and the steamdryness determining at various well points (U.S. Pat. No. 4,581,926dated Apr. 15, 1986). According to the known method a specialrotation-element device should be moved down to a well, measurementsshould be made of the coolant rate and density following the steam flowconsumption and the dryness calculation at any point along the welllength. The method shortages are in an extra device and computationalcomplexity.

The technical effect of the invention implemented is a simple, a fieldapplicable, and an extra equipment-free method for determining steamdryness directly under thermal heavy viscosity oil reservoirstimulation. The technical effect is achieved by adding the gasnon-condensed in a well when flooding, to the pumpdown saturated steam,and the steam dryness at the various well points can be calculated bythe following formula:

$Q_{m} = {Q_{s} \cdot \frac{z_{{gas},m}}{z_{{gas},s}} \cdot \frac{z_{{steam},s}}{z_{{steam},m}} \cdot \frac{P_{{steam},m}}{P_{{steam},s}} \cdot \frac{P_{s} - P_{{steam},s}}{P_{m} - P_{{steam},m}}}$

where,

Q_(s) is the borehole mouth steam dryness,

P_(s) is the borehole mouth injection pressure,

P_(m) is the total system pressure at the given point (m) of theborehole mouth,

P_(steam,s) is the partial steam pressure at the condensationtemperature T_(s) in the borehole mouth,

P_(steam,m) is the partial steam pressure at the condensationtemperature T_(m) at the given point (m) of the borehole mouth,

z is the steam and non-condensed gas compressibility in the borehole (s)mouth and at the given point (m) of the borehole mouth.

With this, the total and partial pressures P_(m), P_(steam,s) andP_(steam,m) are determined by temperatures T_(s) and T_(m) measured atthese points (pre- and post-non-condensed gas injection).

The non-condensed gas is no more than 30% total steam-gas mixture.

By adding up to 30% of the non-condensed gas will allow a well-markedtemperature fall alarm (30° up to 50°) to be used when calculating. Fromthe economic and technical point of view, this is not advisable to addmore non-condensed gas (due to substantial decreasing in temperature).

For non-condensed gases, hydrocarbon gases can be used such as methane,ethane, propane, butane etc. being non-condensed ones under the presentoperation conditions, and nitrogen, carbon dioxide etc. too.

The suggested method for determining steam dryness is based on the factthat the non-condensed gas occurrence of the mixture will vary partialsteam pressure. In doing so, the steam condensation temperature willvary too. Therefore, the borehole temperature or pressure measurementscan be used to evaluate the steam dryness. According to the Dalton's lawthe partial pressure of the component p_(j) will be equal to the productof the mole fraction of this component in gas y_(j) and the totalpressure of the system p:

p_(j)=y_(j)p  (1)

Therefore, adding the non-condensed gas to the steam flooded will resultin reducing the partial steam pressure (total injection pressure will bekept the same). Due to the constant well heat losses to surroundingrocks the steam will condense to water along the whole well length. Asthe steam dryness decreases, the mole fraction of the steam in a gasphase y_(steam) will be reduced too. This, in its turn, will result invariation in the partial steam pressure (as to (1)) and correspondingreduction in the steam condensation temperature.

Thus, knowing the steam dryness in the borehole mouth, its pressure andtemperature values are the possibility for determining the steam drynessalong the whole well by using the down-the-hole pressure and temperaturemeasurements. According to the Dalton's law (1) and the conditionequation for real gases

$\begin{matrix}{\frac{P_{s}}{{z_{{steam},s}\frac{w_{{steam},s}}{\mu_{steam}}} + {z_{{gas},s}\frac{w_{gas}}{\mu_{gas}}}} = \frac{P_{{steam},s}}{z_{{steam},s}\frac{w_{{steam},s}}{\mu_{steam}}}} & (2)\end{matrix}$

where,P_(s) is the borehole mouth injection pressure, P_(steam,s) is thepartial steam pressure at the condensation temperature T_(s) in theborehole mouth, w,μ,z are the mass flow, the mole mass, and the steamand non-condensed gas condensability, respectively.

Therefore, mass steam and water rates will be as follows;

$\begin{matrix}{w_{{steam},s} = \frac{P_{{steam},s} \cdot \left( {z_{{gas},s}\frac{w_{gas}}{\mu_{gas}}} \right)}{\left( {P_{s} - P_{{steam},s}} \right) \cdot \left( {z_{{steam},s}\frac{1}{\mu_{steam}}} \right)}} & (3) \\{w_{{water},s} = \frac{\left( {1 - Q_{s}} \right) \cdot w_{{steam},s}}{Q_{s}}} & (4)\end{matrix}$

where, Q_(s) is the known borehole mouth steam dryness.

The above relationships are also valid for any point in the boreholemouth (m), where P_(m) is the total system pressure at the given point(at the given depth), and P_(steam,m) is the partial steam pressure atthe condensed temperature T_(m) at the given point. Based on a materialbalance equation and the fact that for an additive the non-condensed gasis used, an equation for determining steam dryness at the point (m) canbe obtained:

$\begin{matrix}{Q_{m} = {Q_{s} \cdot \frac{z_{{gas},m}}{z_{{gas},s}} \cdot \frac{z_{{steam},s}}{z_{{steam},m}} \cdot \frac{P_{{steam},m}}{P_{{steam},s}} \cdot \frac{P_{s} - P_{{steam},s}}{P_{m} - P_{{steam},m}}}} & (5)\end{matrix}$

The method should be implemented as follows:

With thermal heavy viscosity oil reservoir stimulation, theQ_(s)=95%-dry steam should be well down-flooded.

The borehole mouth pressure and temperature will be P_(s)=70 atm andT_(s)=287.7° C., respectively, the bottom-hole ones will be P_(m)=60 atmand T_(m)=277.5° C., respectively.

On adding the non-condensed gas (methane) in amount of 20% totalsteam-gas mixture mass the borehole mouth and the bottom-holetemperature measurements showed as follows:

-   -   a) the borehole mouth temperature T_(s) decreases down to 273°        C.,    -   b) the bottom-hole temperature T_(s) decreases down to 251° C.

Water-phase diagrams (P-T) have provided corresponding partial pressuressuch as, P_(steam,s)=56 atm and P_(steam,m)=39 atm.

Let us use an assumption that the gases are ideal (z=1).

Substituting to formula (5), we obtain as follows:

Q_(m)=0.44

Therefore, the bottom-hole steam dryness constitutes 44%.

A certain advantage of the method suggested should be easiness and fieldapplicability. There is no need in mounting extra downhole measuringequipment. Temperature measurements could be obtained both by usingdistributed temperature measurement systems and by standard temperaturelogging.

1. The method for determining saturated steam dryness including steam flooding and determining steam dryness at various well points characterized in that; The gas non-condensed in a well when flooding will be added to the saturated steam pumpdown, and the steam dryness at the various well points can be calculated by the following formula: $Q_{m} = {Q_{s} \cdot \frac{z_{{gas},m}}{z_{{gas},s}} \cdot \frac{z_{{steam},s}}{z_{{steam},m}} \cdot \frac{P_{{steam},m}}{P_{{steam},s}} \cdot \frac{P_{s} - P_{{steam},s}}{P_{m} - P_{{steam},m}}}$ where, Q_(s) is the borehole mouth steam dryness, P_(s) is the borehole mouth injection pressure, P_(m) is the total system pressure at the given point (m) of the borehole mouth, P_(steam,s) is the partial steam pressure at the condensation temperature T_(s) in the borehole mouth, P_(steam,m) is the partial steam pressure at the condensation temperature T_(m) at the given point (m) of the borehole mouth, z is the steam and non-condensed gas compressibility in the borehole (s) mouth and at the given point (m) of the borehole mouth.
 2. The method according to claim 1, characterized in that, the total and partial pressures P_(m), P_(steam,s) and P_(steam,m) are determined by temperatures T_(s) and T_(m) measured at these points (pre- and post-injection of the gas non-condensed).
 3. The method according to claim 1, characterized in that the non-condensed gas should be no more than 30% the total steam-gas mixture. 